Additive to enhance sag stability of drilling fluid

ABSTRACT

A method including providing a drilling fluid that comprises a base fluid, a weighting agent, and a sag stability enhancer, wherein the sag stability enhancer comprises polyethylene glycol (PEG) having a molecular weight of greater than or equal to about 200 g/mol; and placing the drilling fluid in a subterranean formation via a wellbore penetrating the subterranean formation. A method including forming a fluid comprising a base fluid, a weighting agent, and from about 0.5 ppb (1.4 kg/m 3 ) to about 30 ppb (85.5 kg/m 3 ) of a sag stability enhancer, wherein the sag stability enhancer comprises a glycol; and introducing the fluid into at least a portion of a well. A drilling fluid containing a base fluid, a weighting agent, and a sag stability enhancer comprising polyethylene glycol (PEG) having a molecular weight of greater than or equal to about 200 g/mol.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a national stage entry of PCT/US2016/029601 filedApr. 27, 2016, said application is expressly incorporated herein in itsentirety.

BACKGROUND

The present disclosure generally relates to drilling fluids for use insubterranean applications, and, in particular, drilling fluids havingreduced barite sag potential and extended emulsion stability.

A drilling fluid or drilling mud is a designed fluid that is circulatedthrough a wellbore to facilitate a drilling operation. Actions of adrilling fluid can include, without limitation, removing drill cuttingsfrom the wellbore, cooling and lubricating the drill bit, aiding in thesupport of the drill pipe and the drill bit, and providing a hydrostatichead to maintain integrity of the wellbore walls and preventing blowoutsfrom occurring.

It is often desirable to change the density of a drilling fluid tomaintain pressure balance within a wellbore and keep the wellborestable. Changing the density is usually accomplished by adding aweighting agent to the drilling fluid. Often, the weighting agent isbarite (barium sulfate), sometimes spelled baryte. Barite is aninsoluble material, and additional stabilizers are usually added to thedrilling fluid to maintain the salt in a suspended state. Stabilizerscan include, for example, thickeners, viscosifying agents, gellingagents and the like. Use of stabilizers can be problematic if theyincrease the viscosity of the drilling fluid so much that effectivepumping into the wellbore becomes difficult.

In lower viscosity drilling fluids, even in the presence of addedstabilizers, barite can begin to settle from the drilling fluid in acondition known as “barite sag.” Other solid weighting agents can alsoexperience sag. As used herein, the term “barite sag” refers to asettling of barite or other solid weighting agent in a drilling fluid.Barite sag is undesirable because it can lead to an uneven fluid densityin the wellbore and altered well performance. Barite sag can beparticularly problematic in cases where the drilling fluid cannot beeffectively sheared before being pumped downhole. For example, baritesag can occur during transport of a drilling fluid to an offshoredrilling platform. In other instances, barite sag can occur downholewhen the drilling fluid spends a longer than usual time downhole orthere are inadequate downhole shearing forces. In extreme cases, baritesag can deposit a bed of barite on the low side of the wellbore,eventually leading to stuck pipe and possible abandonment of thewellbore.

The difference in a drilling fluid's surface density at the well headand the density while pumping or circulating downhole is typicallyreferred to as the equivalent circulating density (ECD). Severaldrilling fluids having low ECDs have been developed that containorganophilic clay or organolignite additives. As used herein, the term“organophilic clay” refers to clays that have been treated with acationic surfactant (e.g., a dialkylamine cationic surfactant or aquaternary ammonium compound) or like surface treatments. Organoligniteadditives have been prepared in a like manner. Organophilic claystypically swell in non-polar organic solvents, thereby forming openaggregates that are believed to be a suspending structure for barite andother solid weighting agents in invert emulsion drilling fluidscontaining these agents. Although such additives are effective atmediating barite sag in many cases, exposure of organophilic clays, inparticular, to drill cuttings can alter the performance of the drillingfluid. For example, organophilic clays may prevent the formation ofideal or near ideal thixotropic fluids that are initially viscous butthen thin at a later time. Incorporation of drill cuttings oftenincreases the fluid viscosity dramatically, and organophilic additiveshave a tendency to create a robust gel structure under static conditionsthat may be difficult to break when reestablishing circulation. This maylead to high ECD pressure spikes (and concomitantly poor cement jobs)when circulation is restarted.

Drilling fluids not containing organophilic clays or organoligniteadditives can have emulsion structures that are sensitive to lowconcentrations of solids therein. In these cases, a minimumconcentration of solids can be required to achieve adequate emulsionstability over time. Many drilling applications rely upon the downholeintroduction of solids into the drilling fluid in the form of drillcuttings in order to stabilize the drilling fluid's emulsion structure.In these cases, the introduction of ˜2-3% drill cutting solids istypically considered necessary to maintain downhole emulsion stability.Although downhole introduction of drill cutting solids providessatisfactory performance in many cases, there are notable exceptionswhen this is not the case. In some instances, drilling operations maynot incorporate sufficient amounts of drill cutting solids into thedrilling fluid to achieve satisfactory emulsion stability. In otherinstances, the drill cutting solids may not be of the correct type toachieve satisfactory emulsion stability. For example, sand formationsand salt formations can provide drill cutting solids that fail tosatisfactorily stabilize the drilling fluid's emulsion structure. Instill other instances, the drilling fluid may experience significant sagduring delivery to a drilling site.

Sag stability of drilling fluids is a growing concern, as drillingwellbores becomes more challenging, e.g., drilling of deviated wellboresand high pressure/high temperature (HPHT) environments. Generally, thehotter temperatures encountered during drilling, the greater thelikelihood of barite sag, and the deeper the drilling environment, thenarrower the ECD window may be. The ECD window is the pressuredifference between the pore pressure and the fracture gradient, or thewindow the ECD has to stay within to avoid a “kick” of formation fluidsand/or a fracturing of the formation. Low ECD drilling fluids require alow viscosity while maintaining suspension properties of the drillingfluid to reduce or eliminate the occurrence of sag. Instances of saginstability increase the likelihood of losing wellbore control, possiblyeither fracturing the wellbore or taking a kick. Accordingly, an ongoingneed exists for drilling fluids with enhanced sag stability.

BRIEF DESCRIPTION OF THE DRAWINGS

The following FIGURES are included to illustrate certain aspects of thepresent disclosure, and should not be viewed as exclusive embodiments.The subject matter disclosed is capable of considerable modification,alteration, and equivalents in form and function, as will occur to onehaving ordinary skill in the art and having the benefit of thisdisclosure.

FIG. 1 depicts an embodiment of a system configured for delivering theenhanced sag stability drilling fluid of embodiments described herein toa downhole location.

DETAILED DESCRIPTION

The present disclosure provides a drilling fluid for use in subterraneanapplications, said drilling fluid having enhanced sag stability, andalso provides methods of use of such drilling fluids.

Herein disclosed is a method comprising: providing a drilling fluid thatcomprises a base fluid; a weighting agent; and a sag stability enhancer,wherein the sag stability enhancer comprises polyethylene glycol (PEG)having a molecular weight of greater than or equal to about 200 g/mol;and placing the drilling fluid in a subterranean formation via awellbore penetrating the subterranean formation. In embodiments, the PEGhas a molecular weight in the range of from about 200 to about 20,000g/mol. In embodiments, the drilling fluid comprises less than about 30ppb (85.5 kg/m³) of the sag stability enhancer. In embodiments, thedrilling fluid comprises from about 0.5 ppb (1.4 kg/m³) to about 20 ppb(57.0 kg/m³) of the sag stability enhancer. in embodiments, theweighting agent comprises barite. In embodiments, the weighting agenthas a d₅₀ of less than or equal to about 25 μm. In embodiments, the basefluid is selected from the group consisting of oil based fluids. Thedrilling fluid may comprise a low ECD fluid, designed to add less thanabout 1.5 ppg (180 kg/m³) density change due to circulation in thewellbore. In embodiments, the drilling fluid has a density in the rangeof from about 9 ppg (1080 kg/m³) to about 18 ppg (2160 kg/m³). Inembodiments, the drilling fluid is in the form of an invert emulsion. Inembodiments, the base fluid is a water-based fluid.

In embodiments, the drilling fluid exhibits a density change afterstatic aging for at least 120 hours that is at least about 60% less thanthat of the same drilling fluid absent the sag stability enhancer. Inembodiments, the drilling fluid has a density that changes by less thanabout 5% over at least 120 hours of static aging. In embodiments, thedrilling fluid, when compared to a same drilling fluid without the sagstability enhancer, restricts the increase in plastic viscosity to about25% or less, and has at least one characteristic selected from the groupconsisting of: an increased yield point, a reduced density change uponstatic aging, a reduced sag factor upon static aging, and combinationsthereof. Placing the drilling fluid in a subterranean formation via awellbore penetrating the subterranean formation may further comprisessubjecting the drilling fluid to a temperature of greater than at leastabout 300° F. (148.9° C.) for a time period of at least 120 hours.

Also disclosed herein is a method comprising: forming a fluid comprisinga base fluid; a weighting agent; and from about 0.5 ppb (1.4 kg/m³) toabout 30 ppb (85.5 kg/m³) of a sag stability enhancer, wherein the sagstability enhancer comprises a glycol; and introducing the fluid into atleast a portion of a well. In embodiments, the fluid has a density thatchanges by less than about 5% over at least 120 hours of static aging.In embodiments, the sag stability enhancer comprises polyethylene glycolhaving a molecular weight in the range of from about 200 to about 20,000g/mol. In embodiments, the weighting agent comprises barite, and thebarite has a d₅₀ of less than or equal to about 25 μm. In embodiments,the fluid is an oil-based drilling fluid. In embodiments, the fluid isin the form of an invert emulsion, and is designed to add less thanabout 1.5 ppg (180 kg/m³) density change due to circulation. Inembodiments, the fluid, when compared to a same drilling fluid withoutthe sag stability enhancer, restricts the increase in plastic viscosityto about 25% or less, and has at least one characteristic selected fromthe group consisting of: an increased yield point, a reduced densitychange upon static aging, a reduced sag factor upon static aging, andcombinations thereof. The base fluid may be a water-based fluid.

Also disclosed herein is a drilling fluid comprising: a base fluid; aweighting agent; and a sag stability enhancer comprising polyethyleneglycol (PEG) having a molecular weight of greater than or equal to about200 g/mol. In embodiments, the PEG has a molecular weight in the rangeof from about 200 to about 20,000 g/mol. The drilling fluid may compriseless than about 30 ppb (85.5 kg/m³) of the sag stability enhancer. Thedrilling fluid may comprise from about 0.5 ppb (1.4 kg/m³) to about 20ppb (57.0 kg/m³) of the sag stability enhancer. In embodiments, theweighting agent comprises barite. In embodiments, the weighting agentcomprises barite having a d₅₀ of less than or equal to about 25 μm.

The base fluid may be selected from the group consisting of oil basedfluids. The drilling fluid may be in the form of an invert emulsion. Inembodiments, the drilling fluid comprises a low ECD fluid designed toadd less than about 1.5 ppg (180 kg/m³) density change due tocirculation. In embodiments, the drilling fluid has a density in therange of from about 9 ppg (1080 kg/m³) to about 18 ppg (2160 kg/m³). Inembodiments, the base fluid is a water-based fluid. In embodiments, thedrilling fluid exhibits a density change after static aging for at least120 hours that is at least about 60% less than that of the same drillingfluid absent the sag stability enhancer. In embodiments, the drillingfluid has a density that changes by less than about 5% over at least 120hours of static aging. In embodiments, the drilling fluid, when comparedto a same drilling fluid without the sag stability enhancer, restrictsthe increase in plastic viscosity to about 25% or less, and has at leastone characteristic selected from the group consisting of: an increasedyield point, a reduced density change upon static aging, a reduced sagfactor upon static aging, and combinations thereof.

General Measurement Terms

Unless otherwise specified or unless the context otherwise clearlyrequires, any ratio or percentage means by weight.

If there is any difference between U.S. or Imperial units, U.S. unitsare intended.

If all that is needed is to convert a volume in barrels to a volume incubic meters without compensating for temperature differences, then 1bbl equals 0.159 m³ or 42 U.S. gallons.

Unless otherwise specified, mesh sizes are in U.S. Standard Mesh.

The micrometer (μm) may sometimes be referred to herein as a micron.

The conversion between pound per gallon (lb/gal or ppg) and kilogram percubic meter (kg/m³) is: 1 lb/gal=(1 lb/gal)×(0.4536 kg/lb)×(gal/0.003785m³)=120 kg/m³.

The conversion between pound per barrel (lb/bbl or ppb) and kilogram percubic meter (kg/m³) is: 1 lb/bbl=(1 lb/bbl)×(0.4536 kg/lb)×(bbl/0.159m³)=2.85 kg/m³.

The conversion between pound per square foot (lb/ft²) and kilogram persquare meter (kg/m²) is: 1 lb/ft²=4.9 kg/m².

The features and advantages provided by the sag stability enhancer anddrilling fluids of this disclosure will be readily apparent to thoseskilled in the art upon a reading of the following description of theembodiments.

As noted hereinabove, the present disclosure relates to drilling fluidsfor use in subterranean applications, and, in particular, drillingfluids having reduced sag potential and extended emulsion stability.More specifically, the present disclosure provides, in embodiments,drilling fluids that exhibit desirable rheological properties, withenhanced sag stability, in embodiments enabling the maintenance of lowECDs over extended periods of time. For example, a drilling fluidaccording to this disclosure may exhibit enhanced sag stability, withouta concomitant substantial increase in rheology.

Although the description that follows is primarily directed to drillingfluids containing barite particles, drilling fluids containing likeweighting agents can also be stabilized by making use of the presentdisclosure.

Of the many advantages of the present disclosure, only a few of whichare discussed or alluded to herein, the present disclosure generallyprovides facile methods for drilling wellbores in certain subterraneanformations. Drilling fluids according to this disclosure may exhibitimproved viscosity, solids suspension, and/or fluid loss control underwellbore conditions (e.g., temperatures up to or above 300° F. (176.7°C.)) for extended periods of time. This is accomplished via drillingfluids that have a reduced potential for barite sag and increasedemulsion stability over extended periods of time. Emulsion stability canbe reflected in the drilling fluid having a relatively stable densityand rheological profile over extended aging times. The drilling fluidsof the present disclosure utilize a sag stability enhancer comprisingglycol (e.g., polyethylene glycol) to confer extended density stabilityto the drilling fluid, particularly at downhole temperatures. Densitystabilization makes the present drilling fluids desirable for extendeddownhole use. Without limitation, such density stabilization may beespecially desirable in highly deviated wellbores, wellbores havingnarrow annuli, and wellbores in depleted formations, where the drillingfluids can spend a considerable amount of time downhole. In addition,the density stabilization provided by the sag stability enhancer mayallow the present drilling fluids to be transported to a drilling sitewithout density gradients forming in the drilling fluid duringtransport.

Drilling fluids according to the present disclosure may advantageouslybe formed via the introduction of the disclosed sag stability enhancerthereto prior to pumping downhole. In this manner, the emulsionstructure of the drilling fluid and the distribution of a weightingagent therein may be stabilized. According to embodiments, theintroduction of drill cutting solids during a drilling operation andextensive downhole shearing are not necessarily required to stabilizethe emulsion while downhole. The earlier introduction of the sagstability enhancer may allow the composition of the drilling fluid to bemaintained in a desired range for conferring emulsion stability, whileproducing a desired rheological performance over extended periods oftime. In addition, the earlier introduction of the sag stabilityenhancer may allow the drilling fluid to be pumped downhole withoutnecessarily applying shear prior to or during the pumping operation inorder to redisperse a weighting agent. Accordingly, in embodiments, adrilling fluid according to this disclosure can be formulated at aproduction facility, sheared and then transported to a drilling site fordownhole pumping.

An additional advantage of the drilling fluids according to embodimentsof this disclosure is that the sag stability enhancer is present in anamount that is sufficient to confer extended density stability to thedrilling fluid without substantially degrading its rheologicalperformance compared to a drilling fluid not containing the sagstability enhancer. Thus, drilling fluids according to this disclosureremain very amenable to downhole pumping and demonstrate desirabledownhole performance characteristics. In addition, the incorporation ofthe sag stability enhancer into the drilling fluids of this disclosurecan result in certain beneficial rheological enhancements, as furtherdiscussed herein below.

It has been conventional in the art to simulate downhole performance ofa drilling fluid through static aging of a drilling fluid sample underconditions comparable to those experienced downhole. By monitoring thedrilling fluid sample's rheological performance and density as afunction of time under simulated downhole conditions, an indicator ofdownhole performance and sag potential can be ascertained. Typically, ithas been conventional to conduct these measurements after 16 hours ofstatic aging. This period of time has been considered by those ofordinary skill in the art to be sufficiently indicative of the long termdensity stability and rheological performance of the drilling fluidwhile downhole. However, some drilling fluids that exhibit acceptableperformance at 16 hours of aging may exhibit substantially differentdensity and rheological profile at more extended aging times (e.g., upto 120 hours). Therefore, a drilling fluid that might seem suitable fordownhole use based on the 16-hour aging data might, in fact, beunacceptable during extended downhole residence times. Drilling fluidsaccording to this disclosure containing a sag stability enhancer asprovided herein advantageously provide relatively stable densities andgood rheological performance over extended periods of time, which maymake them quite desirable for certain downhole operations.

To determine if a drilling fluid exhibits enhanced sag stability, sagtesting and rheological performance testing may be performed asdescribed in the Examples hereinbelow. In general, enhanced sagstability is found to exist if the density of the bottom 25% of drillingfluid increases by less than about 10% of the base fluid density. Thepercent change is over at least about 120 hours of static aging and/orif the low shear rheological profile of the drilling fluid changes byless than about ±25%, as measured by the dial reading at a rotation rateof 6 revolutions per minute (rpm) or less on a Fann Model 35 Viscometer.Drilling fluids having these qualities are presented in the Exampleshereinbelow.

The present disclosure describes methods using drilling fluids accordingto this disclosure. In some embodiments, the methods comprise providinga drilling fluid comprising a base fluid, a weighting agent, and a sagstability enhancer according to this disclosure, and placing thedrilling fluid in a subterranean formation via a wellbore penetratingthe subterranean formation. Although referred to herein as a ‘drilling’fluid, it is to be understood that the sag stability enhancer accordingto this disclosure may be suitable for a variety of fluids utilized in awellbore, such as, without limitation, fluids utilized for drilling,completion and stimulation operations (such as fracturing, runningcasing liners), sand control treatments such as installing gravel pack,cementing, maintenance and reactivation.

Sag Stability Enhancer

A drilling fluid according to this disclosure comprises a sag stabilityenhancer. The sag stability enhancer comprises glycol. In embodiments,the sag stability enhancer comprises one or more of ethylene glycol,diethylene glycol, triethylene glycol, propylene glycol, butyleneglycol, polyethylene glycol (also referred to herein as ‘PEG’),polypropylene glycol, polyethylene-propylene glycol, and the like. Inembodiments, the sag stability enhancer comprises a water solubleglycol, which herein refers to a glycol that is miscible with freshwater at 20° C. In embodiments, the sag stability enhancer comprises apreferentially oil-soluble glycol, which herein refers to a glycol whichat 20° C. is miscible at all proportions with oil but has limitedmiscibility with water, specifically less than 10% by volume of theglycol is miscible with fresh water, such that the addition of greaterthan 10% by volume of the glycol mixed with fresh water results in twophases.

In embodiments, the sag stability enhancer comprises at least onecomponent having the formula H(OCH₂CH₂)_(n)OH. In embodiments, n isgreater than or equal to 4. In embodiments, the glycol is polyethyleneglycol. In embodiments, the sag stability enhancer comprises PEG havingan average molecular weight of greater than or equal to about 200, 250,300, 350, 400, 450, 500, 550, or 600 grams per mole (g/mol). Inembodiments, the sag stability enhancer comprises PEG having an averagemolecular weight of less than about 250, 300, 350, 400, 450, 500, 550,or 600 grams per mole (g/mol). In embodiment, the PEG has an averagemolecular weight in the range of from about 200 to about 20,000 g/mol.In embodiments, the PEG has an average molecular weight in the range offrom about 200 to about 10,000 g/mol. In embodiments, the PEG has anaverage molecular weight in the range of from about 200 to about 1,000g/mol. In embodiments, the sag stability enhancer comprises at least oneglycol that is liquid at room temperature and pressure. In embodiments,the PEG has an average molecular weight in the range of from about 200to about 600 g/mol. In embodiments, the PEG has an average molecularweight in the range of from about 200 to about 500 g/mol. Inembodiments, the PEG has an average molecular weight in the range offrom about 200 to about 400 g/mol. In embodiments, the PEG has anaverage molecular weight in the range of from about 200 to about 300g/mol. In embodiments, the PEG has an average molecular weight in therange of from about 200 to about 250 g/mol. In embodiments, the sagstability enhancer comprises at least one glycol that is solid orsemisolid at room temperature and pressure. In embodiments, the sagstability enhancer comprises monodisperse PEG. In embodiments, the sagstability enhancer comprises polydisperse PEG.

A drilling fluid according to this disclosure may comprise an amount ofsag stability enhancer suitable to enhance the sag stabilitysufficiently for a given application. It will be apparent to one ofskill in the art, upon reading this disclosure, how to determine such asuitable amount of sag stability enhancer. However, in embodiments, adrilling fluid according to this disclosure may contain from about 0.5pounds per barrel (ppb or lb/bbl) to about 30 ppb (from about 1.4 kg/m³to about 85.5 kg/m³), from about 0.5 ppb to about 20 ppb (from about 1.4kg/m³ to about 57.0 kg/m³), from about 0.5 ppb to about 10 ppb (fromabout 1.4 kg/m³ to about 28.5 kg/m³), from about 1 ppb to about 10 ppb(from about 2.85 kg/m³ to about 28.5 kg/m³), or from about 2 ppb toabout 6 ppb (from about 5.7 kg/m³ to about 17.1 kg/m³) of the sagstability enhancer. In embodiments, a drilling fluid according to thisdisclosure contains greater than or equal to about 0.5, 1, 2, 3, 4, or 5ppb (greater than or equal to about 1.4, 2.85, 5.7, 8.6, 11.4, or 14.2kg/m³) of the sag stability enhancer. In embodiments, a drilling fluidaccording to this disclosure contains less than or equal to about 30,25, 20, 15, 10, 9, 8, 7, 6, 5, 4, 3, or 2 ppb (less than or equal toabout 85.5, 71.3, 57.1, 42.8, 28.5, 25.7, 22.8, 20.0, 17.1, 14.2, 11.4,8.6, or 5.7 kg/m³) of the sag stability enhancer.

Weighting Agent

Drilling fluids according to this disclosure comprise a weighting agent.In embodiments, the weighting agent is present to produce a desireddensity in a drilling fluid according to this disclosure. Inembodiments, the weighting agent comprises barite particles. Weightingagents other than barite can be used in any of the embodiments describedherein. In some embodiments, weighting agents such as, by way ofnon-limiting example, hematite, magnetite, iron oxides, illmenite,siderite, celestite, dolomite, olivine, calcite, magnesium oxides,halites and the like can be used. In some embodiments, weighting agentssuch as calcium carbonate, strontium sulfate, or manganese tetraoxidecan be used. Other weighting agents can also be envisioned by those ofordinary skill in the art.

In embodiments, incorporation of the sag stability enhancer of thisdisclosure enables the use of more economical weighting agent. Forexample, by way of non-limiting example, a drilling fluid according tothis disclosure may contain larger barite particles than would besuitable in a drilling fluid absent the disclosed sag stabilityenhancer. Generally, particles that are overly large might settle/sag,while overly fine particles may not provide adequate weighting, may bemore expensive to obtain because of the grinding involved, and may tendto cause an increase in fluid loss relative to the same volume of largerparticles. However, by Stokes law, smaller particles settle slower andhence have inherently higher sag resistance. The enhanced sag stabilityprovided by incorporation of the herein-disclosed sag stability enhancermay enable utilization of larger particles of weighting agent than couldbe successfully utilized in the same drilling fluid absent the sagstability enhancer. The median particle size, or d₅₀, is the diameterabove which half of the particles are smaller and half are larger insize. In embodiments, at least 40%, 50%, 60%, 70%, 80%, 90%, or 100% byweight of the barite particles are provided by a barite source having amedian particle size (d₅₀) of greater than or equal to about 10, 15, 20,25, 30, 35, 40, 45, or 50 micrometers. In some embodiments, a majority(i.e., greater than 50 weight percent) of the barite particles areprovided by a barite source having a median particle size (d₅₀) of 15,20, or 25 microns or more. In embodiments, the weighting agent comprisesAPI barite (discussed further hereinbelow), 325 mesh barite (discussedfurther hereinbelow), or a combination thereof. The barite may have aspecific gravity of greater than or equal to about 4.0, 4.1, 4.2, 4.3,4.4, or 4.5 g/cm³.

In some embodiments, from about 6% to about 80% of the particles of theweighting agent are 20 microns or larger in size. In embodiments, atleast about 30%, 40%, 50%, 60%, 70%, 80%, 90%, or 95% of the particlesof the weighting agent are greater than or equal to about 15, 20, 25,30, or 35 micrometers in size. In some embodiments, at least a portionof the weighting agent used in the present embodiments comprise AmericanPetroleum Institute (API)-barite particles or barite particles having alike size distribution. According to API standards, API barite has aparticle size distribution ranging substantially between 3 and 74microns and a specific gravity of at least 4.20 g/cm³. Table 1 shows alisting of particle size distribution measured in a typical sample ofAPI barite. API barite may have a d₅₀ of about 20 μm to 25 μm.

TABLE 1 TYPICAL PSD OF API BARITE Size Range, microns Typical Amount ofParticles, %  <1 0.85 1-4 7.40 4-8 6.25  8-12 5.25 12-16 4.75 16-204.50 >20 71.00 100%

Although removal of large particles from the barite sourceadvantageously decreases the propensity for barite sag to occur,Applicants have found that incorporation of the sag stability enhancerof this disclosure enables, in embodiments, utilization of largerparticles of weighting agent, such as API barite.

In embodiments, a portion of the weighting agent may comprise baritehaving a reduced d₅₀ relative to that of API barite. As a non-limitingexample, smaller barite particles can be prepared by grinding API bariteor any other barite source and passing the ground barite through a sieveor mesh screen to provide barite particles having a desired size range.For example, in some embodiments, ground barite can be passed through a325 mesh screen to produce barite particles that are less than 45microns in size. Other sizing techniques and size ranges may beenvisioned by those of ordinary skill in the art. Table 2 shows alisting of particle size distributions in a typical ground barite thatcan be passed through a 325 mesh screen. Such a 325 mesh barite may havea median particle size or d₅₀ of about 10-20 μm.

TABLE 2 TYPICAL PSD OF 325 MESH (0.045 mm) BARITE Size Range, micronsTypical Amount of Particles, %  <1 1.80 1-4 13.70 4-8 15.00  8-12 14.2512-16 16.25 16-20 14.50 >20 24.50 100%

In some embodiments, the weighting agent/barite particles of the presentdisclosure are substantially spherical. Although certain types of sizedbarite have been disclosed, one of ordinary skill in the art given thebenefit of the present disclosure can appreciate that suitable baritesources having a desired average particle size, density, and/or particlesize distribution can be used in the drilling fluids of this disclosure,and selection thereof will depend on the specific application.Desirably, as noted hereinabove, utilization of a sag stability enhanceraccording to this disclosure will broaden the suitable sources of bariteby enhancing the sag stability of a fluid into which it is incorporated.

A drilling fluid according to this disclosure may comprise from about 7ppb to about 22 ppb, from about 8 ppb to about 20 ppb, or from about 8.5ppb to about 19 ppb (i.e., from about 19.9 to about 62.7 kg/m³, fromabout 22.8 kg/m³ to about 57.0 kg/m³, or from about 24.2 kg/m³ to about54.2 kg/m³) weighting agent.

Base Fluid

Drilling fluids according to this disclosure comprise a base fluid. Inembodiments, the drilling fluid is oil based. The oil based fluid maycomprise one or more natural and/or synthetic oil based fluid. Inembodiments, a drilling fluid according to this disclosure is waterbased. In embodiments, the drilling fluid is an invert emulsion, whichis an oil based emulsion comprising an oleaginous fluid continuous phaseand an aqueous fluid internal phase. Such emulsions are commonlyreferred to as water-in-oil emulsions in which an oil or like non-polarhydrophobic compound forms the continuous phase and water or awater-miscible but oleaginous fluid immiscible compound forms theinternal phase. In embodiments, a drilling fluid according to thisdisclosure comprises an invert emulsion, comprising an oleaginous fluidcontinuous phase, an aqueous fluid internal phase, and a surfactant.

Oil Base Fluids: As used herein, the term ‘oleaginous fluid’ refers to amaterial having the properties of an oil or like non-polar hydrophobiccompound. Illustrative oleaginous fluids suitable for use in embodimentsof this disclosure include, for example, (i) esters prepared from fattyacids and alcohols, or esters prepared from olefins and fatty acids oralcohols; (ii) linear alpha olefins, isomerized olefins having astraight chain, olefins having a branched structure, isomerized olefinshaving a cyclic structure, and olefin hydrocarbons; (iii) linearparaffins, branched paraffins, poly-branched paraffins, cyclic paraffinsand isoparaffins; (iv) mineral oil hydrocarbons; (v) glyceride triestersincluding, for example, rapeseed oil, olive oil, canola oil, castor oil,coconut oil, corn oil, cottonseed oil, lard oil, linseed oil, neatsfootoil, palm oil, peanut oil, perilla oil, rice bran oil, safflower oil,sardine oil, sesame oil, soybean oil and sunflower oil; (vi) naphtheniccompounds (cyclic paraffin compounds having a formula of C_(n)H_(2n)where n is an integer ranging between about 5 and about 30); (vii)diesel; (viii) aliphatic ethers prepared from long chain alcohols; and(ix) aliphatic acetals, dialkylcarbonates, and mixtures thereof. As usedherein, fatty acids and alcohols or long chain acids and alcohols referto acids and alcohols containing about 6 to about 22 carbon atoms, orabout 6 to about 18 carbon atoms, or about 6 to about 14 carbon atoms.In some embodiments, such fatty acids and alcohols have about 6 to about22 carbon atoms comprising their main chain. One of ordinary skill inthe art will recognize that the fatty acids and alcohols may alsocontain unsaturated linkages.

As used herein, the term ‘aqueous fluid’ refers to a material comprisingwater or a water-miscible but oleaginous fluid-immiscible compound.Illustrative aqueous fluids suitable for use in embodiments of thisdisclosure include, for example, fresh water, sea water, a brinecontaining at least one dissolved organic or inorganic salt, a liquidcontaining water-miscible organic compounds, and the like.

In embodiments, in a drilling fluid according to this disclosure, anoleaginous fluid continuous phase and an aqueous fluid internal phaseare present in a ratio of at least about 50:50. This ratio is commonlystated as the oil-to-water ratio (OWR). That is, in the presentembodiments, a drilling fluid having a 50:50 OWR comprises 50%oleaginous fluid continuous phase and 50% aqueous fluid internal phase.In embodiments, drilling fluids according to this disclosure have an OWRranging between about 50:50 to about 98:2, including all subrangestherein between. In embodiments, drilling fluids of this disclosure havean OWR ranging between about 74:26 and about 80:20, including allsub-ranges therein between. In embodiments, the drilling fluids have anOWR of about 75:25 or greater. In embodiments, the drilling fluids havean OWR of about 80:20 or greater. In embodiments, the drilling fluidshave an OWR of about 85:15 or greater. In embodiments, the drillingfluids have an OWR between about 90:10 and 60:40, including allsubranges there between. One of ordinary skill in the art will recognizethat lower OWRs can more readily form emulsions that are suitable forsuspending barite and other weighting agents therein. However, one ofordinary skill in the art will also recognize that an OWR that is toolow may prove overly viscous for downhole pumping.

A drilling fluid according to this disclosure may contain a surfactant.In general, the surfactant(s) are not particularly limited. Inembodiments, the surfactant(s) is present to assist with stabilizationof an invert emulsion. Without limitation, illustrative surfactantssuitable for use in drilling fluids according to some embodiments ofthis disclosure include acid hydrolyzable mixed alkyldiethanol amides,alkyl glucosides, polyalkylglucosides, alkylalkoxypolydimethylsiloxanes,polyalkyldimethylsiloxanes, fatty acids, soaps of fatty acids, amidoamines, polyamides, polyamines, oleate esters, imidazoline derivatives,oxidized crude tall oil, organic phosphate esters, alkyl aromaticsulfates, alkyl aromatic sulfonates, alkyl sulfates, alkyl sulfonates,monoesters of polyalkoxylated sorbitan, polyester polyols, aliphaticalcohol esters, aromatic alcohol esters, ammonium salts of polyacrylicacid, and ammonium salts of 2-acrylamido-2-methylpropane sulfonicacid/acrylic acid copolymer. In some embodiments, the surfactant is apolyamide. In other embodiments, the surfactant is a fatty acid.

Generally, such surfactants may be present in an amount that does notinterfere with the use of the drilling fluids and further facilitatesthe development of enhanced density stability and rheological propertiesas described herein. In some embodiments, the surfactants are present inan invert emulsion drilling fluid according to embodiments of thisdisclosure in an amount less than about 10% by volume of the drillingfluid. In other embodiments, the surfactants are present in invertemulsion drilling fluids according to embodiments of this disclosure inan amount less than about 3% by volume of the drilling fluid.

Aqueous Base Fluids

In embodiments, a drilling fluid according to this disclosure comprisesan aqueous base fluid. The aqueous base fluid of the present embodimentscan generally be from any source, provided that the fluids do notcontain components that might adversely affect the stability and/orperformance of the drilling fluids of the present disclosure. In variousembodiments, the aqueous base fluid can comprise fresh water, saltwater, seawater, brine, or an aqueous salt solution. In someembodiments, the aqueous base fluid can comprise a monovalent brine or adivalent brine. Suitable monovalent brines can include, for example,sodium chloride brines, sodium bromide brines, potassium chloridebrines, potassium bromide brines, and the like. Suitable divalent brinescan include, for example, magnesium chloride brines, calcium chloridebrines, calcium bromide brines, and the like. In some embodiments, theaqueous base fluid can be a high density brine. As used herein, the term‘high density brine’ refers to a brine that has a density of about9.5-10 lbs/gal or greater (1.1 g/cm³-1.2 g/cm³ or greater).

Other Additives: A drilling fluid of this disclosure may optionallycomprise any number of additional additives. Examples of such additionaladditives include, without limitation, gelling agents, fluid losscontrol agents, corrosion inhibitors, rheology control modifiers orthinners, viscosity enhancers, temporary viscosifying agents, filtrationcontrol additives, high temperature/high pressure control additives,emulsification additives, surfactants, acids, alkalinity agents, pHbuffers, fluorides, gases, nitrogen, carbon dioxide, surface modifyingagents, tackifying agents, foamers, scale inhibitors, catalysts, claycontrol agents, biocides, bactericides, friction reducers, antifoamagents, bridging agents, dispersants, flocculants, H₂S scavengers, CO₂scavengers, oxygen scavengers, friction reducers, breakers, relativepermeability modifiers, resins, particulate materials (e.g., proppantparticulates), wetting agents, coating enhancement agents, filter cakeremoval agents, surfactants, defoamers, shale stabilizers, oils, and thelike. One or more of these additives (e.g., bridging agents) maycomprise degradable materials that are capable of undergoingirreversible degradation downhole. A person skilled in the art, with thebenefit of this disclosure, will recognize the types of additives thatmay be included in the drilling fluids of the present disclosure for aparticular application, without undue experimentation.

As noted above, the sag stability enhancer of the present disclosure mayadvantageously be incorporated in a drilling fluid according to thisdisclosure prior to introduction of the drilling fluid in a subterraneanformation. Such drilling fluids may be formulated at a productionfacility and mixed by applying a shearing force to the drilling fluid.Application of the shearing force may result in formation of an emulsionwhich is stabilized by the sag stability enhancer. Once formed, theemulsion may be stable in the absence of a shearing force, such that thedrilling fluids of the present disclosure have a reduced tendency towardbarite sag. In embodiments, the sag stability enhancer inhibits and/orreduces sag of the barite particles for at least or equal to about 60,70, 80, 90, 100, 110, or 120 hours. In embodiments, barite saginhibition is measured by the drilling fluid having a change in densityof less than about 5% over this time period.

In some embodiments, the drilling fluid has a density that changes byless than about 7.5% over at least or equal to about 60, 70, 80, 90,100, 110, or 120 hours of static aging. In some embodiments, thedrilling fluid has a density that changes by less than about 7% over atleast or equal to about 60, 70, 80, 90, 100, 110, or 120 hours of staticaging. In some embodiments, the drilling fluid has a density thatchanges by less than about 6% over at least or equal to about 60, 70,80, 90, 100, 110, or 120 hours of static aging. In some embodiments, thedrilling fluid has a density that changes by less than about 5% over atleast or equal to about 60, 70, 80, 90, 100, 110, or 120 hours of staticaging. In embodiments, the drilling fluid has a density that changes byless than about 4.5% over at least or equal to about 60, 70, 80, 90,100, 110, or 120 hours of static aging. In embodiments, the drillingfluid has a density that changes by less than about 4% over at least orequal to about 60, 70, 80, 90, 100, 110, or 120 hours of static aging.In embodiments, the drilling fluid has a density that changes by lessthan about 3% over at least or equal to about 60, 70, 80, 90, 100, 110,or 120 hours of static aging. In still other embodiments, the drillingfluid has a density that changes by an amount between about 1% to about5%, about 1% to about 4.5%, or about 1% to about 4% over at least orequal to about 40, 50, 60, 70, 80, 90, 100, 110, or 120 hours of staticaging. In embodiments, the static aging is at a temperature of greaterthan or equal to about 300° F. (148.9° C.), 310° F. (154.4° C.), 320° F.(160.0° C.), 330° F. (165.6° C.), 340° F. (171.1° C.), or 350° F.(176.7° C.).

In some embodiments, the acceptable density change of the drilling fluidvaries in proportion to the weight of the drilling fluid. For example,for a 14 lb/gal drilling fluid, the change in density of less than about5% over the time period of static aging may be suitable. However, forheavier drilling fluids, the change in density may desirably be lessover the static aging period. For example, for a 16 lb/gal drillingfluid, a suitable change in density may be less than about 4.5% over agiven time period of static aging, and for an 18 lb/gal, the change indensity may be less than about 4% over that static aging period. In theheavier drilling fluids, such density change values provide the same 0.7lb/gal variance that occurs for a 14 lb/gal drilling fluid when a 5%change in density occurs. In embodiments, a drilling fluid according tothis disclosure exhibits a change in density over a static aging periodthat is less than or equal to about 2 lb/gal, 1.75 lb/gal, 1.5 lb/gal,1.25 lb/gal, 1.0 lb/gal, 0.9 lb/gal, 0.8 lb/gal, 0.75 lb/gal, 0.7lb/gal, 0.6 lb/gal, 0.5 lb/gal, 0.4 lb/gal, 0.3 lb/gal, 0.25 lb/gal, 0.2lb/gal, or 0.1 lb/gal (i.e., less than or equal to about 240, 210, 180,150, 120, 108, 96, 90, 84, 72, 60, 48, 36, 30, 24, or 12 kg/m³).

A drilling fluid according to this disclosure may exhibit a densitychange upon static aging (for example, static aging at 350° F. (167.7°C.) for five days) that is reduced by at least or about 50, 60, 65, 70,or 75% relative to a drilling fluid having the same composition absentthe sag stability enhancer.

In embodiments, a drilling fluid according to this disclosure is a lowrheology fluid that may provide an ECD increase of less than 1.6, 1.5,1.4, 1.3, or 1.2 ppg over the static density. In embodiments, a drillingfluid according to this disclosure has a low density or mud weight.Incorporation of a sag stability enhancer according to this disclosuremay enable usage of a low mud weight fluid, while inhibiting undesirablebarite sag. For example, in embodiments, a drilling fluid according tothis disclosure has a formulation density in the range of from about 8to about 20 ppg (960 to about 2400 kg/m³), from about 8.5 to about 19ppg (1020 to about 2280 kg/m³), from about 9 to about 18 ppg (1080 toabout 2160 kg/m³), or from about 9 ppg to about 17 ppg (1080 to about2040 kg/m³). In embodiments, a drilling fluid according to thisdisclosure has a formulation density in the range of from about 8, 9,10, 11, or 12 ppg to about 15, 16, 17, 18 or 19 ppg (i.e., from about960, 1080, 1200, 1320, or 1440 kg/m³ to about 1800, 1920, 2040, 2160, or2280 kg/m³). In embodiments, a drilling fluid according to thisdisclosure has a formulation density of equal to or about 8, 9, 9.5, 10,10.5, 11, 11.5, 12, 12.5, 13, 13.5, 14, 14.5, 15, 15.5, 16, 16.5, 17,17.5, 18, 18.5, 19, 19.5 or 20 ppg (960, 1080, 1140, 1200, 1260, 1320,1380, 1440, 1500, 1560, 1620, 1680, 1740, 1800, 1860, 1920, 1980, 2040,2100, 2160, 2220, 2280, 2340, or 2400 kg/m³). Without limitation, a lowdensity drilling fluid according to this disclosure may have enhancedsag stability and suitable rheology such that it proves particularlyapplicable in high temperature and/or low ECD applications. Inembodiments, a drilling fluid according to this disclosure is a low ECDfluid, adding less than or equal to about 1.5, 1, or 0.5 ppg (180, 120,or 60 kg/m³) due to circulation.

In various embodiments, drilling fluids according to this disclosure aresubstantially free of organophilic clays and/or organophilic lignite. Insome embodiments, an organophilic clay-free drilling fluid according tothis disclosure comprises an oleaginous fluid continuous phase, anaqueous fluid internal phase, a surfactant, barite particles or a likeweighting agent, and a sag stability enhancer according to thisdisclosure. As will be apparent to those of skill in the art, a drillingfluid according to this disclosure may comprise additional optionalproducts, such as, without limitation, fluid loss control agents,viscosifiers, thinners, lubricants, etc.

In embodiments, incorporation of the sag stability enhancer in drillingfluids according to this disclosure may not result in a substantialchange of the high shear rheological profile of the drilling fluid. Asused herein, a substantial change in the rheological profile of thedrilling fluid is defined as a 600 rpm rheology measurement increasingby more than about 20% or 25% after incorporation of sag stabilityenhancer. Stated another way, the incorporation of sag stabilityenhancer in drilling fluids according to this disclosure may notsubstantially change the rheological profile of the disclosed drillingfluids by making them become overly viscous. In embodiments, the 600 rpmrheology measurement of a drilling fluid according to this disclosureafter hot rolling at 150° F. (65.6° C.) for 16 hours increases by lessthan or equal to about 12, 11, 10, 9, 8, or 7% relative to the samedrilling fluid absent the sag stability enhancer. In embodiments, the600 rpm rheology measurement of a drilling fluid according to thisdisclosure after static aging at 350° F. (176.7° C.) for five daysincreases by less than or equal to about 12, 11, 10, 9, 8, or 7%relative to the same drilling fluid absent the sag stability enhancer.In embodiments, the 300 rpm rheology measurement (i.e., the viscosity incentipoise (cP)) of a drilling fluid according to this disclosure afterhot rolling at 150° F. (65.6° C.) for 16 hours increases by less than orequal to about 17, 16, 15, 14, 13, 12, or 11% relative to the samedrilling fluid absent the sag stability enhancer. In embodiments, the300 rpm rheology measurement of a drilling fluid according to thisdisclosure after static aging at 350° F. (176.7° C.) for five daysincreases by less than or equal to about 10, 9, 8, 7, or 6% relative tothe same drilling fluid absent the sag stability enhancer. Inembodiments, a drilling fluid according to this disclosure has a lowviscosity, or one that has a viscosity as determined as the reading at300 rpm measured at 120° F. (48.9° C.) that is less than or equal toabout 60, 50, 40, or 30 cP.

In embodiments, the low shear rheological profile of a drilling fluidaccording to this disclosure is within +25% of the same drilling fluidabsent the sag stability enhancer, as measured by the dial reading at arotation rate of 6 rpm or less on a Fann Model 35 Viscometer. Inembodiments, the 6 rpm rheology measurement of a drilling fluidaccording to this disclosure after hot rolling at 150° F. (65.6° C.) for16 hours increases by less than or equal to about 20%, 15%, 10%, 5%, or0% relative to the same drilling fluid absent the sag stabilityenhancer. In embodiments, the 6 rpm rheology measurement of a drillingfluid according to this disclosure after static aging at 350° F. (176.7°C.) for five days increases by less than or equal to about 15%, 14%,13%, 12%, 11%, or 10% relative to the same drilling fluid absent the sagstability enhancer. In embodiments, the 3 rpm rheology measurement of adrilling fluid according to this disclosure after hot rolling at 150° F.(65.6° C.) for 16 hours increases by less than or equal to about 25, 20,15, 12.5, 10, 5, or 0% relative to the same drilling fluid absent thesag stability enhancer. In embodiments, the 3 rpm rheology measurementof a drilling fluid according to this disclosure after static aging at350° F. (176.7° C.) for five days increases by less than or equal toabout 17%, 16%, 15%, 14%, 13%, 12%, or 11% relative to the same drillingfluid absent the sag stability enhancer.

A drilling fluid according to this disclosure may exhibit a sag factor(discussed further in the Examples hereinbelow) that is reduced by atleast or about 1.5, 1.6, 1.7, 1.8, 1.9, 2.0, 2.1, 2.2, 2.3, or 2.4%relative to a drilling fluid having the same composition absent the sagstability enhancer.

As used herein, the term ‘yield point’ refers to a parameter of theBingham plastic model, where yield point refers to the yield stressextrapolated to a shear rate of zero. This extrapolation is commonlymade from the highest shear rate readings at 600 and 300 rpm on a Fann35 rheometer using standard F1 springs. In some embodiments, drillingfluids of this disclosure have yield points after hot rolling at 150° F.(65.6° C.) for 16 hours ranging from about 10 lb/100 ft² to about 13lb/100 ft² (from about 479 Pa to about 622 Pa). In embodiments, drillingfluids according to this disclosure exhibit yield points after staticaging at 350° F. (176.7° C.) for five days that are at least or about 5,6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, or 20% higher thanthe same drilling fluid absent the sag stability enhancer.

As used herein, the term ‘gel strength’ refers to the shear stressmeasured at a low shear rate after a drilling fluid has set quiescentlyfor a set period of time. According to standard API procedures, the gelstrength is measured after setting for 10 seconds and 10 minutes,although measurements at longer time intervals can also be made such as,for example, 30 minutes or 16 hours. The shear stress is related to theyield stress by the following three-parameter equation:τ=τ₀ +k(γ)n,  (1)

where τ is the shear stress, τ₀ is the yield stress, k(γ) is theconsistency, and n is a real number. As noted above, k(y) and n are fitgraphically or calculated from the 600 and 300 rpm rheometer readings.As used herein, ‘yield stress’ refers to the torque required to juststart a fluid moving from rest in a rheometer measurement. The yieldstress is also commonly extrapolated from several viscometer readings atdiffering shear rates. In rheometer measurements, the yield stress canbe approximated by the 3 rpm reading on the standard Fann 35 rheometer.In various embodiments, drilling fluids of the present embodiments havegel strengths ranging from about 5 to about 30 measured after either 10or 30 minutes of quiescence.

Methods of Use

Also disclosed herein are methods of introducing a drilling fluidaccording to this disclosure into a wellbore. The methods of the presentdisclosure may be employed in any subterranean application where adrilling fluid of this disclosure may be suitable. In an embodiment, amethod of treating a wellbore comprises providing a drilling fluidaccording to this disclosure, and using the wellbore fluid during adrilling, drill-in, completions, logging, casing/liner running,abandoning, work-over, or stimulating operation. The drilling fluid maybe pumped down to the bottom of a well through a drill pipe, where thefluid emerges through ports in a drill bit, for example. The drillingfluid may be used in conjunction with any drilling operation for whichit is suitable, as will be apparent to those of skill in the art. Suchdrilling operations may include, without limitation, vertical drilling,extended reach drilling, and directional drilling. It will be apparentto those of skill in the art that drilling muds having a variety offormulations may be prepared, with specific formulations depending onthe state of drilling a well at a particular time, for example,depending on the particular formation being drilled and/or the depth.The drilling fluids described hereinabove may be adapted, for example,to provide enhanced drilling muds for use under conditions of hightemperature and/or having a narrow ECD window. Such high temperature maycomprise a temperature ranging from about 100° F. (37.8° C.) to 350° F.(176.7° C.) or greater, or a temperature of at least about 300° F.(148.9° C.), 325° F. (162.8° C.), 350° F. (176.7° C.), or 375° F.(190.6° C.). Drilling muds for use in such elevated temperatureapplications may be referred to as high temperature drilling muds. Anarrow ECD window may comprise an ECD window of less than or equal toabout 1.5 ppg, 1 ppg, or 0.5 ppg (i.e., less than or equal to about 180kg/m³, 120 kg/m³, or 60 kg/m³). Drilling muds for use in such low ECDapplications may be referred to as low ECD drilling muds. Low ECD mudsmust generally have a low viscosity, while providing suitable holecleaning and sufficient resistance to sag of the weighting agent.

The drilling fluids of the present disclosure may be prepared by anysuitable means known in the art. In some embodiments, the drillingfluids may be prepared at a well site or at an offsite location. Onceprepared, a drilling fluid of the present disclosure may be placed in atank, bin, or other container for storage and/or transport to the sitewhere it is to be used. In other embodiments, a drilling fluid of thepresent disclosure may be prepared on-site, for example, usingcontinuous mixing, on-the-fly mixing, or real-time mixing methods. Incertain embodiments, these methods of mixing may include methods ofcombining two or more components wherein a flowing stream of one elementis continuously introduced into flowing stream of another component sothat the streams are combined and mixed while continuing to flow as asingle stream as part of the ongoing treatment. The system depicted inFIG. 1 (described below) may be one embodiment of a system and equipmentused to accomplish on-the-fly or real-time mixing.

The methods and compositions of the present disclosure may be usedduring or in conjunction with any operation in a portion of asubterranean formation and/or wellbore, including but not limited todrilling operations, pre-flush treatments, after-flush treatments,hydraulic fracturing treatments, sand control treatments (e.g., gravelpacking), “frac pack” treatments, acidizing treatments (e.g., matrixacidizing or fracture acidizing), wellbore clean-out treatments,cementing operations, workover treatments/fluids, and other operationswhere such a drilling fluid may be useful. For example, the methodsand/or compositions of the present disclosure may be used in the courseof drilling operations in which a wellbore is drilled to penetrate asubterranean formation. In certain embodiments, this may be accomplishedusing the pumping system and equipment used to circulate the drillingfluid in the wellbore during the drilling operation, which is describedbelow.

The drilling fluids of the present disclosure may be provided and/orintroduced into the wellbore or used to drill at least a portion of awellbore in a subterranean formation using any method or equipment knownin the art. In certain embodiments, a wellbore fluid of the presentdisclosure may be circulated in the wellbore using the same types ofpumping systems and equipment at the surface that are used to introducedrilling fluids and/or other treatment fluids or additives into awellbore penetrating at least a portion of the subterranean formation.

The exemplary drilling fluids disclosed herein may directly orindirectly affect one or more components or pieces of equipmentassociated with the preparation, delivery, recapture, recycling, reuse,and/or disposal of the disclosed drilling fluid. For example, and withreference to FIG. 1, the disclosed drilling fluid may directly orindirectly affect one or more components or pieces of equipmentassociated with an exemplary wellbore drilling assembly 100, accordingto one or more embodiments. It should be noted that while FIG. 1generally depicts a land-based drilling assembly, those skilled in theart will readily recognize that the principles described herein areequally applicable to subsea drilling operations that employ floating orsea-based platforms and rigs, without departing from the scope of thedisclosure.

As illustrated, the drilling assembly 100 may include a drillingplatform 102 that supports a derrick 104 having a traveling block 106for raising and lowering a drill string 108. The drill string 108 mayinclude, but is not limited to, drill pipe and coiled tubing, asgenerally known to those skilled in the art. A kelly 110 supports thedrill string 108 as it is lowered through a rotary table 112. A drillbit 114 is attached to the distal end of the drill string 108 and isdriven either by a downhole motor and/or via rotation of the drillstring 108 from the well surface. As the bit 114 rotates, it creates aborehole 116 that penetrates various subterranean formations 118.

A pump 120 (e.g., a mud pump) circulates drilling fluid 122 through afeed pipe 124 and to the kelly 110, which conveys the drilling fluid 122downhole through the interior of the drill string 108 and through one ormore orifices in the drill bit 114. The drilling fluid 122 is thencirculated back to the surface via an annulus 126 defined between thedrill string 108 and the walls of the borehole 116. At the surface, therecirculated or spent drilling fluid 122 exits the annulus 126 and maybe conveyed to one or more fluid processing unit(s) 128 via aninterconnecting flow line 130. After passing through the fluidprocessing unit(s) 128, a “cleaned” drilling fluid 122 is deposited intoa nearby retention pit 132 (i.e., a mud pit). While illustrated as beingarranged at the outlet of the wellbore 116 via the annulus 126, thoseskilled in the art will readily appreciate that the fluid processingunit(s) 128 may be arranged at any other location in the drillingassembly 100 to facilitate its proper function, without departing fromthe scope of the scope of the disclosure.

One or more of the disclosed components may be added to the drillingfluid 122 via a mixing hopper 134 communicably coupled to or otherwisein fluid communication with the retention pit 132. The mixing hopper 134may include, but is not limited to, mixers and related mixing equipmentknown to those skilled in the art. In other embodiments, however,components may be added to the drilling fluid 122 at any other locationin the drilling assembly 100. In at least one embodiment, for example,there could be more than one retention pit 132, such as multipleretention pits 132 in series. Moreover, the retention put 132 may berepresentative of one or more fluid storage facilities and/or unitswhere the disclosed components may be stored, reconditioned, and/orregulated until added to the drilling fluid 122.

As mentioned above, the disclosed drilling fluids may directly orindirectly affect the components and equipment of the drilling assembly100. For example, the disclosed drilling fluids may directly orindirectly affect the fluid processing unit(s) 128 which may include,but is not limited to, one or more of a shaker (e.g., shale shaker), acentrifuge, a hydrocyclone, a separator (including magnetic andelectrical separators), a desilter, a desander, a separator, a filter(e.g., diatomaceous earth filters), a heat exchanger, any fluidreclamation equipment, The fluid processing unit(s) 128 may furtherinclude one or more sensors, gauges, pumps, compressors, and the likeused store, monitor, regulate, and/or recondition the exemplary drillingfluids.

The disclosed drilling fluids may directly or indirectly affect the pump120, which representatively includes any conduits, pipelines, trucks,tubulars, and/or pipes used to fluidically convey the drilling fluidsdownhole, any pumps, compressors, or motors (e.g., topside or downhole)used to drive the drilling fluids into motion, any valves or relatedjoints used to regulate the pressure or flow rate of the drilling fluid,and any sensors (i.e., pressure, temperature, flow rate, etc.), gauges,and/or combinations thereof, and the like. The disclosed drilling fluidmay also directly or indirectly affect the mixing hopper 134 and theretention pit 132 and their assorted variations.

The disclosed drilling fluid may also directly or indirectly affect thevarious downhole equipment and tools that may come into contact with thedrilling fluid such as, but not limited to, the drill string 108, anyfloats, drill collars, mud motors, downhole motors and/or pumpsassociated with the drill string 108, and any MWD/LWD tools and relatedtelemetry equipment, sensors or distributed sensors associated with thedrill string 108. The disclosed drilling fluid may also directly orindirectly affect any downhole heat exchangers, valves and correspondingactuation devices, tool seals, packers and other wellbore isolationdevices or components, and the like associated with the wellbore 116.The disclosed drilling fluid may also directly or indirectly affect thedrill bit 114, which may include, but is not limited to, roller conebits, PDC bits, natural diamond bits, any hole openers, reamers, coringbits, etc.

While not specifically illustrated herein, the disclosed drilling fluidmay also directly or indirectly affect any transport or deliveryequipment used to convey the drilling fluid to the drilling assembly 100such as, for example, any transport vessels, conduits, pipelines,trucks, tubulars, and/or pipes used to fluidically move the drillingfluid from one location to another, any pumps, compressors, or motorsused to drive the drilling fluid into motion, any valves or relatedjoints used to regulate the pressure or flow rate of the drilling fluid,and any sensors (i.e., pressure and temperature), gauges, and/orcombinations thereof, and the like.

The invention having been generally described, the following Examplesare given as particular embodiments of this disclosure and todemonstrate the practice and advantages thereof. It is to be understoodthat the Examples are given by way of illustration only, and are notintended to limit the specification or the claims to follow in anymanner.

EXAMPLES Experimental: Preparation of Drilling Fluids and Methods ofMaking Measurements

Drilling fluid formulations were prepared in accordance with thecomposition outlined in Table 3 and further described hereinbelow.

TABLE 3 BASELINE 16.5 PPG (1980 kg/m³) BARAECD ™ FLUID SYSTEM XP-07 ™Base Oil, bbl (liters) 0.52 (82.7) (varies according to desired mudweight) EZ MUL ® NS Emulsifier, lb (kg) 17.5 (7.9) Lime, lb (kg) 4 (1.8)CaCl₂ Brine, bbl (liters) 0.06 (9.5): (varies according to desired mudweight) BDF-513 ™ Filtration 9 (4.1) Control Agent, lb (kg) TAU-MOD ®Viscosifier, lb (kg) 5 (2.3) BDF-568 ™ Rheology Modifier, 1 (0.45) lb(kg) BARACARB ® 5 Bridging 20 (9.1) Agent, lb (kg) Barite WeightingAgent, lb (kg) 472.3 (214.2) (varies according to desired mud weight)OWR 90/10

The baseline formulation was a BARAECD™ fluid system commerciallyavailable from Halliburton Energy Services in Houston, Tex. BARAECD™ isan invert system comprising an oleaginous base fluid. The drilling fluidformulations comprised XP-07™ synthetic paraffin base fluid that isavailable from Halliburton Energy Services. This drilling fluid thus hada pure normal alkane mixture as the oleaginous fluid continuous phase.As noted in Table 3 hereinabove, in addition to the alkane mixturecontinuous phase, the experimental drilling fluid further contained abrine internal phase comprising 0.06 bbl CaCl₂ brine; EZ MUL® NS orBaraMUL IE-672 emulsifier; BDF-513™ filtration control agent; BDF-568™rheology modifier; BARACARB® 5 bridging agent, which is a ground marblecomposition, having d₅₀ sizes of 5 microns and 50 microns, respectively;and TAU-MOD® viscosifier, which is an amorphous/fibrous material. Theregistered and trademarked components are available from HalliburtonEnergy Services in Houston, Tex.

Mixing was performed on 350 mL quantities of formulated drilling fluidusing a Multimixer Model 9585. The indicated amount of oleaginous basefluid was combined with the emulsifier and mixed for 5 minutes, duringwhich time lime was added. At this time, the sample was removed from themixer, and the brine was added accordingly. Samples were then furthermixed for 10 minutes, and filtration control agent was then added with 5minutes of additional mixing conducted. Calcium carbonate and TAU-MOD®Viscosifier was then added and mixed for 10 minutes. BDF 568™ RheologyModifier was then added and mixed for 5 minutes. The PEG was then added,with subsequent mixing for an additional 5 minutes. Lastly the baritewas added and mixed for 15 minutes. Following mixing, the samples weresheared using a Silverson L4RT high shear mixer equipped with a squarehole screen. Silverson shearing was performed at 7000 rpm for 15minutes. A water bath was maintained around the sample to keep thetemperature below 150° F. The sample was then hot rolled for 16 hours at150° F. (65.6° C.) prior to testing. (Shearing could be performed beforeor after hot rolling.) Hot rolling is a laboratory technique utilized tosimulate downhole circulation at a design temperature for a desiredtime.

Static aging and density measurements were carried out as outlinedbelow.

After preparation and initial characterization of the drilling fluidformulations, samples were placed in aging cells, and the samples wereaged for 5 days (120 hours) at 350° F. (176.7° C.). HPHT Fluid Lossafter hot rolling can be measured (according to API Recommended Practice13B-2, Recommended Practice for Field Testing of Oil-based DrillingFluids, Fifth Edition, American Petroleum Institute, August 2014) on 20μm (micrometer) ceramic discs at 350° F. (176.7° C.). Generally, HPHThere refers to temperatures of greater than 250° F. (121.1° F.). Alltesting for sag measurements was performed after static aging for fivedays at 350° F. (176.7° C.). Measurement of the post-aging density anddetermination of the sag factor were conducted as follows:

1. Procedure:

-   -   1.1 Transfer one laboratory barrel (350 mL) of drilling fluid        into an aging cell;    -   1.2 Close the cell properly, pressurize to 100-500 psi with        nitrogen and check for leaks;    -   1.3 Static age the cell at specified temperature and angle for a        specified period of time;        -   1.3.1 When aging time is completed, cool down the aging cell            to room temperature. Be careful when moving the aging cell            to keep the cell in the same angle as it has been aged;        -   1.3.2 Carefully bleed off the pressure prior to            disassembling the cell;        -   1.3.3 Measure amount of liquid separated on top of drilling            fluid using syringe and measuring cylinder. Report this as            free fluid on top (mL). Then transfer to a Hamilton Beach            cup.

2. Sag Testing:

-   -   2.1 Carefully remove the top strata of the mud and fill a tared        100 mL sag/density cup. Tap the cup several times on the bench        at intervals as the cup is being filled to dislodge and get rid        of entrapped gas. Weigh the top strata and determine the        density;    -   2.2 Remove the mud from the density cup into the Hamilton Beach        cup and clean the sag cup;    -   2.3 Continue taking out mud from the cell into the mud cup        leaving only the last 100 mL at the bottom of the cell (use the        marker to determine the bottom 100 mL). Carefully extrude the        bottom layer and observe any stratification or the general state        of the mud at the bottom. Mix the bottom layer up in the cell;    -   2.4 Transfer the mixed bottom 100 mL mud into the sag/density        cup and determine the density;    -   2.5 Calculate the Sag Factor according to the equation below.    -   2.6 Empty the sag/density cup into the Hamilton Beach cup and        mix the composite mud for 10-15 minutes. Preserve the composite        sample for other mud properties determination if necessary.

3. Calculations: The stability of the fluid is conventionallycharacterized by how the fluid segregates and stratifies during thestatic aging period. The volume of free fluid at the top of the fluidcolumn is measured as well as the density within the segregated andnon-segregated fluid layers. The density contrast between top and bottomof the main body of fluid is used to calculate the Sag Factor of thefluid. Ideally, the Sag Factor should remain 0.5 indicating ahomogeneous mud body. The Sag Factor described the density contrastwithin the main body of fluid that underlies any free fluid but does notrelate the density and homogeneity of this fluid to the original fluiddensity.

-   -   3.1 Sag Factor=(Bottom Strata Density)/(Top Strata        Density+Bottom Strata Density).

Example 1: Sag Stability of Drilling Fluids Containing Various BariteSources

Each of the formulations studied, and for which density changemeasurements are provided in Table 4, contained the same baseline fluidsystem provided in Table 3, with a different source of barite, and 3lb/bbl (359.48 kg/m³) of sag stability enhancer comprising PEG with anaverage molecular weight of about 200 g/mol. The density changemeasurements after static aging (ASA) for five days at 350° F. (176.7°C.) for 8 formulations containing a sag stability enhancer of thisdisclosure, along with the density change measurements determined forbaseline formulations containing the same systems absent the PEG 200 areprovided in Table 4. As noted above, various micronized barite sourceswere used in preparing the tested drilling fluid formulations.Formulation 1 contained a fine grind barite having a particle size ofabout 3 μm. Formulation 2 contained a fine grind barite having a d₅₀ ofabout 3.5 μm. Formulation 3 contained a fine grind barite having a d₅₀of about 4.5 μm. Formulation 4 contained a fine grind barite having ad₅₀ of about 2 μm. Formulation 5 contained a fine grind barite having ad₅₀ of about 3.25 μm. Formulation 6 contained a fine grind barite havinga d₅₀ of about 2.5 μm. Formulation 7 contained a fine grind baritehaving a d₅₀ of about 2.7 μm. Formulation 8 contained a fine grindbarite having a d₅₀ of about 3.0 μm.

TABLE 4 DENSITY CHANGE ASA OF DRILLING FLUIDS CONTAINING VARYING BARITESOURCES, WITH AND WITHOUT PEG DENSITY CHANGE OF BASELINE DENSITYFORMULATION WITH FORMULATION: CHANGE, 3PPB PEG, BARITE SOURCE PPG(KG/M³) PPG (KG/M³) FORMULATION 1 1.29 0.76 FORMULATION 2 1.59 0.72FORMULATION 3 2.34 1.2 FORMULATION 4 0.73 0.28 FORMULATION 5 1.94 0.68FORMULATION 6 1.34 0.97 FORMULATION 7 0.63 0.44 FORMULATION 8 3.2 1.05

As can be seen from the data in Table 4, incorporation of the sagstability enhancer improved the suspension properties (i.e., reduced thedensity change) of the drilling fluid for long periods of time (5 daysstatic aging tested) at elevated temperatures (350° F. (176.7° C.)tested). Improvements in sag stability were seen for every barite sourcetested. The density change upon aging seen in Table 4 is 27.6% to 67.2%less than that seen in the absence of the sag stability enhancer. Inapplications where a density change of 1.25 lb/gal or less (7.6%) isdesired, the usage of the sag stability enhancer of this disclosureenables the use of the barite sources of Formulations 1, 2, 3, 5, 6, and8, wherein the drilling fluids absent the PEG did not provide a suitablylow density change.

Example 2: Sag Stability of Drilling Fluids Containing Various Amountsof Sag Stability Enhancer

The rheological properties of drilling fluid formulations based on afluid system of Table 3, having a baseline density of 16.5 lb/gal (1980kg/m³), and comprising barite and either 0 lb/bbl (0 kg/m³), 3 lb/bbl(8.6 kg/m³), 4 lb/bbl (11.4 kg/m³), or 5 lb/bbl (14.2 kg/m³) of PEG sagstability enhancer (200 g/mol average molecular weight PEG) wereevaluated after aging by hot rolling (AHR) at 66.6° C. (150° F.) for 16hours, and after static aging (ASA) at 350° F. (176.7° C.) for 5 days.Rheology data was obtained according to API Recommended Practice 13B-2,Recommended Practice for Field Testing of Oil-based Drilling Fluids,Fifth Edition, American Petroleum Institute, August 2014, using a FANN®Model 35A direct reading rotational viscometer at 48.9° C. (120° F.) bymeasuring the shear stress of the bob at shear rates between 3 rpm to600 rpm (units: lb/100 ft²), determining the plastic viscosity (PV)(units: centipoise (cP)), the yield point (YP) (units: lb/100 ft²), andthe low shear yield point (Yz) (units: lb/100 ft²). The PV wasdetermined by subtracting the 300 rpm shear stress from the 600 rpmyield stress. The YP was determined by subtracting the PV from the 300rpm shear stress. The low shear yield point is determined by multiplyingthe 3 rpm shear stress reading by two and then subtracting the 6 rpmshear stress.

Rheological data, fluid loss values, density change values, and sagfactors for the various formulations, determined as outlinedhereinabove, are provided in Table 5 hereinbelow.

TABLE 5 RHEOLOGICAL PARAMETERS, FLUID LOSS, DENSITY CHANGE, AND SAGFACTOR FOR 16.5 PPG (1980 kg/m³) FORMULATION COMPRISING BARITE ANDVARIOUS AMOUNTS OF SAG STABILITY ENHANCER PEG 200 3 lb/bbl 4 lb/bbl 5lb/bbl NONE (8.6 kg/m³) (11.4 kg/m³) (14.2 kg/m³) Rheology, AHR ASA AHRASA AHR ASA AHR ASA 120° F. (48.9° C.) 600 RPM, lb/100 ft² 64 81 70 8671 86 70 90 300 RPM, lb/100 ft² 36 49 40 53 42 52 41 54 6 RPM, lb/100ft² 5 10 5 11 6 11 5.5 11.5 3 RPM, lb/100 ft² 4 9 4 10 5 10 4.5 10.5 PV,cP 28 32 30 33 29 34 29 36 YP lb/100 ft² 8 17 10 20 13 18 12 18 FluidLoss, mL — 5.2 — 7.0 — 8.6 — 8.0 Density Change, — 1.94 — 0.68 — 0.71 —0.59 lb/gal (kg/m³) (232.8) (81.6) (85.2) (70.8) Sag Factor — 0.526 —0.513 — 0.516 — 0.513

As seen from the data in Table 5, the rheological profile ischaracteristic of a low ECD fluid, for the baseline and inventiveformulations. However, the sag stability after static aging (asindicated by the reduced change in density) improves on average ˜60-70%.The high shear rheological profile of drilling fluids according to thisdisclosure comprising sag stability enhancer exhibit similar high shearrheological profile as the baseline formulation containing no PEG, afterstatic aging. For example, the dial readings at a rotation rate of 600rpm for the drilling formulations according to this disclosurecomprising 3 lb/bbl, 4 lb/bbl, and 5 lb/bbl PEG increase by only 6.2%,6.2%, and 11.1%, respectively, relative to the baseline formulation,while the dial readings at 300 rpm (i.e., the apparent viscosity of thefluid) increase by only 8.2%, 6.1%, and 10.2%, respectively, relative tothe baseline formulation. After static aging, the dial readings at arotation rate of 6 rpm for the drilling formulations according to thisdisclosure comprising 3 lb/bbl, 4 lb/bbl, and 5 lb/bbl PEG increase by10.0%, 10.0%, and 15.0%, respectively, relative to the baselineformulation, while the dial readings at 3 rpm increase by 11.1%, 11.1%,and 16.7%, respectively, relative to the baseline formulation.

Additionally, upon static aging, the densities of the drillingformulations according to this disclosure comprising 3 lb/bbl, 4 lb/bbl,and 5 lb/bbl PEG change by 4.1%, 4.3%, and 3.6%, respectively, while thedensity of the baseline formulation changes by 11.8%. Thus, the densitychange of the drilling formulations according to this disclosurecomprising 3 lb/bbl, 4 lb/bbl, and 5 lb/bbl PEG change by 64.9%, 63.4%,and 69.6% less, respectively, than the baseline formulation, upon staticaging. The plastic viscosity for the drilling formulations according tothis disclosure comprising 3 lb/bbl, 4 lb/bbl, and 5 lb/bbl PEG increaseby 3.1%, 6.3%, and 12.5%, respectively, after static aging, relative tothe baseline formulation, while the yield point increases by 17.6%,5.9%, and 5.9%, respectively, relative to the baseline formulation. Asseen in Table 5, the sag factor of the drilling fluids according to thisdisclosure, comprising 3 lb/bbl, 4 lb/bbl, and 5 lb/bbl PEG, is alsoreduced after static aging by about 2.5%, 1.9%, and 2.5%, respectively,relative to the baseline formulation containing no PEG.

The present disclosure is well adapted to attain the ends and advantagesmentioned herein, as well as those that are inherent therein. A drillingfluid according to this disclosure may significantly enhance sagstability, which may facilitate economic production and utilization ofsuch drilling fluids, for example by enabling the usage of a greatervariety of weighting agents, and/or usage over a wider temperature rangeand/or range of mud weights. Such drilling fluids may prove especiallyuseful in applications having a narrow ECD window.

The particular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of the present disclosure. While compositions and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps. Allnumbers and ranges disclosed above may vary by some amount. Whenever anumerical range with a lower limit and an upper limit is disclosed, anynumber and any included range falling within the range is specificallydisclosed. In particular, every range of values (of the form, “fromabout a to about b,” or, equivalently, “from approximately a to b,” or,equivalently, “from approximately a-b”) disclosed herein is to beunderstood to set forth every number and range encompassed within thebroader range of values. Also, the terms in the claims have their plain,ordinary meaning unless otherwise explicitly and clearly defined by thepatentee. Moreover, the indefinite articles “a” or “an”, as used in theclaims, are defined herein to mean one or more than one of the elementthat it introduces. If there is any conflict in the usages of a word orterm in this specification and one or more patent or other documents,the definitions that are consistent with this specification should beadopted.

Embodiments disclosed herein include:

A: A method comprising: providing a drilling fluid that comprises a basefluid; a weighting agent; and a sag stability enhancer, wherein the sagstability enhancer comprises polyethylene glycol (PEG) having amolecular weight of greater than or equal to about 200 g/mol; andplacing the drilling fluid in a subterranean formation via a wellborepenetrating the subterranean formation.

B: A method comprising: forming a fluid comprising a base fluid; aweighting agent; and from about 0.5 ppb (1.4 kg/m³) to about 30 ppb(85.5 kg/m³) of a sag stability enhancer, wherein the sag stabilityenhancer comprises a glycol; and introducing the fluid into at least aportion of a well.

C: A drilling fluid comprising: a base fluid; a weighting agent; and asag stability enhancer comprising polyethylene glycol (PEG) having amolecular weight of greater than or equal to about 200 g/mol.

Each of embodiments A, B, and C may have one or more of the followingadditional elements: Element 1: wherein the PEG has a molecular weightin the range of from about 200 to about 20,000 g/mol. Element 2: whereinthe sag stability enhancer comprises polyethylene glycol having amolecular weight in the range of from about 200 to about 20,000 g/mol.Element 3: wherein the drilling fluid or fluid comprises less than about30 ppb (85.5 kg/m³) of the sag stability enhancer. Element 4: whereinthe drilling fluid or fluid comprises from about 0.5 ppb (1.4 kg/m³) toabout 20 ppb (57.0 kg/m³) of the sag stability enhancer. Element 5:wherein the weighting agent comprises barite. Element 6: wherein theweighting agent has a d₅₀ of less than or equal to about 25 μm. Element7: wherein the base fluid is selected from the group consisting of oilbased fluids. Element 8: wherein the drilling fluid or fluid is in theform of an invert emulsion. Element 9: wherein the drilling fluid orfluid comprises a low ECD fluid, designed to add less than about 1.5 ppg(180 kg/m³) density change due to circulation in the wellbore. Element10: wherein the drilling fluid or fluid has a density in the range offrom about 9 ppg (1080 kg/m³) to about 18 ppg (2160 kg/m³). Element 11:wherein the base fluid is a water-based fluid. Element 12: wherein thedrilling fluid or fluid exhibits a density change after static aging forat least 120 hours that is at least about 60% less than that of the samedrilling fluid absent the sag stability enhancer. Element 13: whereinthe drilling fluid or fluid has a density that changes by less thanabout 5% over at least 120 hours of static aging. Element 14: whereinthe drilling fluid or fluid, when compared to a same drilling fluid orfluid without the sag stability enhancer, restricts the increase inplastic viscosity to about 25% or less, and has at least onecharacteristic selected from the group consisting of: an increased yieldpoint, a reduced density change upon static aging, a reduced sag factorupon static aging, and combinations thereof. Element 15: wherein placingthe drilling fluid or fluid in a subterranean formation or introducingthe fluid into at least a portion of a well via a wellbore penetratingthe subterranean formation further comprises subjecting the drillingfluid or fluid to a temperature of greater than at least about 300° F.(148.9° C.) for a time period of at least 120 hours

While preferred embodiments of the invention have been shown anddescribed, modifications thereof can be made by one skilled in the artwithout departing from the teachings of this disclosure. The embodimentsdescribed herein are exemplary only, and are not intended to belimiting. Many variations and modifications of the invention disclosedherein are possible and are within the scope of the invention. Use ofthe term “optionally” with respect to any element of a claim is intendedto mean that the subject element is required, or alternatively, is notrequired. Both alternatives are intended to be within the scope of theclaim.

Numerous other modifications, equivalents, and alternatives, will becomeapparent to those skilled in the art once the above disclosure is fullyappreciated. It is intended that the following claims be interpreted toembrace all such modifications, equivalents, and alternatives whereapplicable.

What is claimed is:
 1. A method comprising: providing a drilling fluidthat comprises a base fluid; a weighting agent; and a sag stabilityenhancer, wherein the sag stability enhancer comprises polyethyleneglycol (PEG) having a molecular weight in the range of from about 200g/mol to about 450 g/mol; and placing the drilling fluid in asubterranean formation via a wellbore penetrating the subterraneanformation.
 2. The method of claim 1 wherein the drilling fluid comprisesless than about 30 ppb (85.5 kg/m³) of the sag stability enhancer. 3.The method of claim 2 wherein the drilling fluid comprises from about0.5 ppb (1.4 kg/m³) to about 20 ppb (57.0 kg/m³) of the sag stabilityenhancer.
 4. The method of claim 1, wherein the weighting agentcomprises barite.
 5. The method of claim 4, wherein the weighting agenthas a d₅₀ of less than or equal to about 25 μm.
 6. The method of claim1, wherein the base fluid is selected from the group consisting of oilbased fluids.
 7. The method of claim 6, wherein the drilling fluid is inthe form of an invert emulsion.
 8. The method of claim 1, wherein thedrilling fluid comprises a low ECD fluid, designed to add less thanabout 1.5 ppg (180 kg/m³) density change due to circulation in thewellbore.
 9. The method of claim 8, wherein the drilling fluid has adensity in the range of from about 9 ppg (1080 kg/m³) to about 18 ppg(2160 kg/m³).
 10. The method of claim 1, wherein the base fluid is awater-based fluid.
 11. The method of claim 1, wherein the drilling fluidexhibits a density change after static aging for at least 120 hours thatis at least about 60% less than that of the same drilling fluid absentthe sag stability enhancer.
 12. The method of claim 1, wherein thedrilling fluid has a density that changes by less than about 5% over atleast 120 hours of static aging.
 13. The method of claim 1, wherein thedrilling fluid, when compared to a same drilling fluid without the sagstability enhancer, restricts the increase in plastic viscosity to about25% or less, and has at least one characteristic selected from the groupconsisting of: an increased yield point, a reduced density change uponstatic aging, a reduced sag factor upon static aging, and combinationsthereof.
 14. The method of claim 1, wherein placing the drilling fluidin a subterranean formation via a wellbore penetrating the subterraneanformation further comprises subjecting the drilling fluid to atemperature of greater than at least about 300° F. (148.9° C.) for atime period of at least 120 hours.
 15. A method comprising: forming afluid comprising a base fluid; a weighting agent; and from about 0.5 ppb(1.4 kg/m³) to about 30 ppb (85.5 kg/m³) of a sag stability enhancer,wherein the sag stability enhancer comprises a glycol; and introducingthe fluid into at least a portion of a well, wherein the sag stabilityenhancer comprises polyethylene glycol having a molecular weight in therange of from about 200 g/mol to about 450 g/mol.
 16. The method ofclaim 15, wherein the fluid has a density that changes by less thanabout 5% over at least 120 hours of static aging.
 17. The method ofclaim 15, wherein the weighting agent comprises barite, and wherein thebarite has a d₅₀ of less than or equal to about 25 μm.
 18. The method ofclaim 15, wherein the fluid is an oil-based drilling fluid.
 19. Themethod of claim 18, wherein the fluid is in the form of an invertemulsion, and is designed to add less than about 1.5 ppg (180 kg/m³)density change due to circulation.
 20. The method of claim 18, whereinthe fluid, when compared to a same fluid without the sag stabilityenhancer, restricts the increase in plastic viscosity to about 25% orless, and has at least one characteristic selected from the groupconsisting of: an increased yield point, a reduced density change uponstatic aging, a reduced sag factor upon static aging, and combinationsthereof.
 21. The method of claim 15, wherein the base fluid is awater-based fluid.